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Earnings Conference CallFourth Quarter 2019
February 11, 2020
2 Q4 2019 Earnings Release Slides
Cautionary Statements Regarding Forward-Looking Information
This presentation contains certain forward-looking statements within the meaning of the Private Securities
Litigation Reform Act of 1995, that are subject to risks and uncertainties. The factors that could cause actual
results to differ materially from the forward-looking statements made by Exelon Corporation, Exelon Generation
Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company,
Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City
Electric Company (Registrants) include those factors discussed herein, as well as the items discussed in (1)
Exelon’s 2018 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part II, ITEM 8.
Financial Statements and Supplementary Data: Note 22, Commitments and Contingencies; (2) Exelon’s Third
Quarter 2019 Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors; (b) Part I, ITEM 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, ITEM 1.
Financial Statements: Note 16, Commitments and Contingencies; and (3) other factors discussed in filings with
the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking
statements, which apply only as of the date of this press release. None of the Registrants undertakes any
obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances
after the date of this presentation.
3 Q4 2019 Earnings Release Slides
Non-GAAP Financial MeasuresExelon reports its financial results in accordance with accounting principles generally accepted in the United
States (GAAP). Exelon supplements the reporting of financial information determined in accordance with GAAP
with certain non-GAAP financial measures, including:
• Adjusted operating earnings exclude certain costs, expenses, gains and losses and other specified items, including mark-to-
market adjustments from economic hedging activities, unrealized gains and losses from nuclear decommissioning trust fund
investments, asset impairments, certain amounts associated with plant retirements and divestitures, costs related to cost
management programs, asset retirement obligations and other items as set forth in the reconciliation in the Appendix
• Adjusted operating and maintenance expense excludes regulatory operating and maintenance costs for the utility businesses
and direct cost of sales for certain Constellation and Power businesses, decommissioning costs that do not affect profit and
loss, the impact from operating and maintenance expense related to variable interest entities at Generation, EDF’s ownership of
O&M expenses, and other items as set forth in the reconciliation in the Appendix
• Total gross margin is defined as operating revenues less purchased power and fuel expense, excluding revenue related to
decommissioning, gross receipts tax, JExel Nuclear JV, variable interest entities, and net of direct cost of sales for certain
Constellation and Power businesses
• Adjusted cash flow from operations primarily includes net cash flows from operating activities and net cash flows from
investing activities excluding capital expenditures, net merger and acquisitions, and equity investments
• Free cash flow primarily includes net cash flows from operating activities and net cash flows from investing activities excluding
certain capital expenditures, net merger and acquisitions, and equity investments
• Operating ROE is calculated using operating net income divided by average equity for the period. The operating income reflects
all lines of business for the utility business (Electric Distribution, Gas Distribution, Transmission).
• EBITDA is defined as earnings before interest, taxes, depreciation and amortization. Includes nuclear fuel amortization
expense.
• Revenue net of purchased power and fuel expense is calculated as the GAAP measure of operating revenue less the GAAP
measure of purchased power and fuel expense
Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the
forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be currently
available, as management is unable to project all of these items for future periods
4 Q4 2019 Earnings Release Slides
Non-GAAP Financial Measures Continued
This information is intended to enhance an investor’s overall understanding of period over period financial
results and provide an indication of Exelon’s baseline operating performance by excluding items that are
considered by management to be not directly related to the ongoing operations of the business. In addition, this
information is among the primary indicators management uses as a basis for evaluating performance, allocating
resources, setting incentive compensation targets and planning and forecasting of future periods.
These non-GAAP financial measures are not a presentation defined under GAAP and may not be comparable to
other companies’ presentations. Exelon has provided these non-GAAP financial measures as supplemental
information and in addition to the financial measures that are calculated and presented in accordance with
GAAP. These non-GAAP measures should not be deemed more useful than, a substitute for, or an alternative to
the most comparable GAAP measures provided in the materials presented.
Non-GAAP financial measures are identified by the phrase “non-GAAP” or an asterisk (*). Reconciliations of
these non-GAAP measures to the most comparable GAAP measures are provided in the appendices and
attachments to this presentation, except for the reconciliation for total gross margin, which appears on slide 53
of this presentation.
5 Q4 2019 Earnings Release Slides
2019 Accomplishments
Maintain industry leading operational excellence
Effectively deploy ~$5.3B of 2019 utility capex
Advocate for policies to enable the utility of the future
Advance PJM energy market price formation reforms
Preserve authority of states to enact state clean energy policies and seek fair compensation for zero-emitting nuclear plants
Grow dividend at 5% rate
Continued commitment to corporate responsibility
• Best on record Customer Satisfaction at all utilities
• ComEd had its best performance ever in both CAIDI and SAIFI; PHI continued to improve its reliability scores in 2019, setting best on record results in SAIFI
• 2019 capacity factor of 95.7%(1) was the highest ever, supporting 155 TWHs of nuclear production and avoiding ~81M metric tonnes of carbon dioxide
• 79% customer renewal rate and 36% new customer win rate for Constellation’s retail power business
• Invested approximately $5.5B to replace aging infrastructure and improve reliability for the benefit of customers
• Maryland PSC approved alternative rate making allowing for multi-year rate plans
• Pepco DC filed multi-year rate plan with DC PSC
• Pennsylvania Senate passed SB596 setting state electrification goals
• Fast start approved by FERC
• Supported PJM-filed proposal to reform reserve market and scarcity rules
• U.S. Supreme Court upheld IL and NY ZEC programs; NJ implemented ZEC program
• Governor Wolf announced plans for Pennsylvania to join the Regional Greenhouse Gas Initiative
• Exelon employees volunteered a record-breaking 250,790 hours and donated approximately $12 million
• Exelon Foundation, Exelon’s family of companies and our employees donated nearly $52 million
• Exelon was recognized for its commitment to diversity by Forbes, DiversityInc, Human Rights Campaign and the Military Times
• Exelon’s total diverse supply spend exceeded $2.0B for the 3rd consecutive year
• Exelon named to Dow Jones Sustainability North America Index for 14th year in a row
(1) Excludes Salem and EDF’s equity ownership share of the CENG Joint Venture. Statistics represent full year 2019 results.
• Increased the dividend to $1.45 from $1.38 per share
Meet or exceed our financial commitments
• Delivered GAAP earnings of $3.01 per share and adjusted (non-GAAP) operating earnings of $3.22 per share
• Exelon Corp. and all of its subsidiaries received credit upgrades
• Committed to $100M of additional cost reductions at ExGen on the Q3 2019 earnings call
6 Q4 2019 Earnings Release Slides
Utility Investments Lead to Customer Benefits
Over the last four years Exelon Utilities have invested $22 billion in resilience, reliability and infrastructure improvements and plan to invest $26 billion over the next four years. These investments have provided benefits to all of our 10 million utility customers:
Improving Customer Service: Each utility had its best ever performance in the Customer Satisfaction Index in 2019
Keeping Electricity Affordable: Residential rates in Baltimore, Chicago, Philadelphia and Washington D.C are below the average for the 20 largest cities and the national average
Enhancing Reliability: Frequency of outages has been reduced by 47% at ComEd and 22% at BGE since 2012. PHI has reduced frequency of outages by 30% since the merger. Duration of outages has been reduced by 52% at ComEd and 38% at BGE since 2012.
Modernizing Gas Infrastructure: Over the last two years BGE and PECO have replaced more than 200 miles of outmoded cast iron and bare steel mains and nearly 30,000 metallic gas services
7 Q4 2019 Earnings Release Slides
7
Customer Benefits are Enabled Through Regulatory Models
Delaware
•Distribution System Investment Charge tracker provides a mechanism to begin recovering gas and electric infrastructure investments for reliability every six months
District of Columbia
•On May 30, 2019, Pepco DC filed first multi-year rate plan
•DC PLUG provides for contemporaneous recovery of reliability and resiliency investments
Illinois
•Recovery through Formula Rate Plan since 2012
•Future Energy Jobs Act allows for recovery on energy efficiency programs
Maryland
•PC 51 allows multi-year rate plans for up to three years; The MDPSC’s Order on February 4, 2020 established a multi-year rate plan pilot and an associated framework
•STRIDE program allows for contemporaneous recovery of the accelerated replacement of aging gas infrastructure
•EmPOWER MD allows for recovery on energy efficiency programs
New Jersey
•PowerAhead program allows for a capital tracker recovery mechanism for resiliency investments
•Investment Infrastructure Program permits the recovery of certain levels of capital through a capital tracker recovery mechanism
Pennsylvania
•Fully projected future test year eliminates regulatory lag and better enables full cost recovery
•DSIC recovery mechanism provides recovery for Long-term Infrastructure Improvement Plan for electric and gas distribution in between rate cases
•Act 58 of 2018 allows for alternative ratemaking including performance-based rates, multi-year rate plans, decoupling and formula rates
8 Q4 2019 Earnings Release Slides
8
Stakeholder Reaction to FERC PJM Capacity Market Order
Illinois
[W]e are extremely concerned by the Federal Energy Regulatory
Commission (FERC)’s unprecedented expansion of the Minimum Offer
Price Rule (MOPR) and how this rash decision will impact PJM’s
Capacity Market. Specifically, we believe this decision will have
crippling impacts on your consumers and our constituents, including
dramatic increases in rates and threatening a burgeoning clean
energy market. -- Members of Congress including Senator Tammy
Duckworth and Representative Cheri Bustos
Consumer Advocates
The Commission’s expanded MOPR will likely prevent many new
capacity resources with beneficial environmental attributes from
clearing PJM’s capacity auctions. The December 19 Order forces
states to either leave PJM’s capacity market or allow the Commission
and PJM to usurp the states’ FPA-protected role regarding capacity
resources. -- Illinois Commerce Commission
The Order’s new MOPR regimen will disconnect the auction, and
PJM’s RPM as a whole, from the region’s actual reliability needs and
from the foundational precept that resources should compete to
provide capacity on the basis of their net costs – those not covered by
revenues received from any source for providing other products or
services. And it will obligate millions of consumers in the PJM service
area to buy far more capacity than they need, at enormous and
unnecessary cost. -- DC Office of People’s Counsel, Maryland Office
of People’s Counsel and New Jersey Division of Rate Counsel
Maryland
The ability of our state to retain some level of sovereignty over energy
policy is paramount given the long-term challenges it must meet. The
order runs counter to meeting those challenges and severely infringes
on the right of states to independently determine and pursue unique
strategies or programs best suited for their citizens and communities.
-- The Maryland Energy Administration
[T]he December 2019 Order forcefully treads on states’ rights as they
pertain to state jurisdiction over both generation resources and
environmental programs . . . As the only alternative presented in the
December 2019 Order, the Commission is effectively inviting states to
exit PJM’s capacity market.
-- Maryland Public Service Commission
New Jersey
Because most supply-side resources receiving state funding are low-
or zero-carbon resources, the Order effectively disregards state clean
energy programs, and instead requires consumers to purchase
reliability services exclusively from emitting resources.
-- New Jersey Board of Public Utilities
Further, the state is proceeding with its march towards 100% clean
energy in the face of federal energy regulators, including the U.S.
Department of Energy (U.S. DOE) and the Federal Energy Regulatory
Commission (FERC), that are actively attempting to support fossil fuel
interests in the PJM region under the guise of promoting “fair”
competition or “resilience” planning. In order to meet the state’s
clean energy targets, consumers in New Jersey must be free to
choose a suite of generation resources that meet state policy goals.
-- New Jersey Energy Master Plan
The FERC ruling was structured specifically to penalize states such as
Illinois that have made cost-saving investments in energy efficiency
and renewable sources of power. But if we act now, we can take the
power back from Washington. -- David Kolata, Citizens Utility Board
and Clean Jobs Coalition Member
9 Q4 2019 Earnings Release Slides
Operations MetricAt CEG Merger (2012) 2015 2019
BGE ComEd PECO PHI BGE ComEd PECO PHI
Electric
Operations
OSHA Recordable Rate
2.5 Beta SAIFI (Outage
Frequency)
2.5 Beta CAIDI (Outage
Duration)
Customer
Operations
Customer Satisfaction N/A
Service Level % of Calls
Answered in <30 sec
Abandon Rate
Gas OperationsPercent of Calls Responded to
in <1 Hour
No Gas
Operations
No Gas
Operations
Overall RankElectric Utility Panel of 24
Utilities(1) 23rd 2nd 2nd 18th
Utility Operating Highlights
(1) Ranking based on results of five key industry performance indicators – CAIDI, SAIFI, Safety, Customer Satisfaction, and Cost per Customer
• All utilities had their best-ever customer satisfaction scores
• ComEd scored in the top decile for service level with ComEd, BGE and PECO achieving best on record performances
• Reliability performance was mixed across the utilities:
o ComEd recorded best ever results in SAIFI and CAIDI
o PHI delivered best ever SAIFI performance
• Top decile Gas odor response for the 7th consecutive year for BGE and PECO and 3rd consecutive year for PHI
Performance
Quartiles
10 Q4 2019 Earnings Release Slides
Best in Class at Generation and Constellation
79% retail power customer renewal
rate
36% power new customer win rate
91% natural gas customer
retention rate
23 month average power contract
term
Average customer duration of more
than 6 years
Stable Retail Margins
Generation Operational Metrics
• Continued best in class performance across our
Nuclear fleet:(1)
− Capacity factor of 95.7%(2,3) was the highest
ever for Exelon (owned and operated units)
− Generated 155 TWhs(2) of zero emitting
nuclear power avoiding approximately 81
million metric tonnes of carbon dioxide
− Carbon emissions rate 4 times less than the
next cleanest generator
− 2019 average refueling outage duration of
21 days, matching Exelon’s 2018 record
• Strong performance across our Fossil and
Renewable fleet:
− Power Dispatch Match: 97.9%
− Renewables Energy Capture: 96.3%
Constellation Metrics
Note: Statistics represent full year 2019 results
(1) Excludes Salem
(2) Excludes EDF’s equity ownership share of the CENG Joint Venture
(3) 2019 capacity factor includes Three Mile Island for the Exelon period of operation prior to planned retirement (January 1 to September 20, 2019)
11 Q4 2019 Earnings Release Slides
2019 Financial Results
• Adjusted (non-GAAP) operating earnings
drivers versus full year guidance of
$3.00 - $3.30:
Full Year 2019 EPS Results
$0.71 $0.71
$0.49 $0.52
$0.54 $0.55
$0.37 $0.37
$1.16$1.31
FY Adjusted
Operating
Earnings*
($0.23)($0.25)
FY GAAP
Earnings
$3.01$3.22
$0.15 $0.15
$0.07 $0.07
$0.12 $0.12
$0.10 $0.10
$0.41 $0.44
Q4 Adjusted
Operating
Earnings*
($0.05)($0.05)
Q4 GAAP
Earnings
$0.79$0.83
Exelon Utilities
– Favorable weather
– Lower costs from major storms
– Higher distribution revenues
– ComEd ROEs*
Exelon Generation
– Favorable O&M
– Realization of R&D tax benefit
– NDT realized gains(1)
– Lower portfolio optimization
– Outages at owned and
contracted assets
– Lower load volumesExGen ComEd
BGE
PECO
PHI HoldCo
Q4 2019 EPS Results
Note: Amounts may not sum due to rounding
(1) Gains related to unregulated sites
12 Q4 2019 Earnings Release Slides
Exelon Utilities Trailing Twelve Month Earned ROEs*
$0 $5 $10 $15 $20 $25 $30 $35 $40 $45 $50
4.0%
0.0%
12.0%
2.0%
6.0%
8.0%
10.0%PHI Utilities
2019E Rate Base ($B)
Consolidated Exelon Utilities
Ea
rne
d R
OE
* (
%) $10.8/9.2%
$30.0/10.3%
Legacy Exelon Utilities
$40.8/10.0%
Q4 2019: Trailing Twelve Month Earned ROEs*
TTM ROEs* PHI Utilities Legacy Exelon Utilities Consolidated Exelon Utilities
Q4 2019 9.2% 10.3% 10.0%
Q4 2018(1) 8.3% 10.1% 9.6%
Note: Represents the twelve-month period ending December 31, 2019 and December 31, 2018. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas
Distribution, and Electric Transmission). Size of bubble based on rate base.
(1) Q4 2018 TTM ROE* for PHI and Consolidated EU was changed from 8.4% and 9.7%, respectively, to 8.3% and 9.6%, respectively, to reflect the correction of an error at PHI
13 Q4 2019 Earnings Release Slides
Our Capital Plan Drives Leading Rate Base Growth
Capital Expenditures ($M)
~$26B of capital planned to be invested at Exelon utilities from 2020–2023 for grid
modernization and resiliency for the benefit of our customers
2,350 2,325 2,400 2,450
1,675 1,7001,800 1,675
1,125 1,2001,225 1,200
1,300 1,2001,125 1,150
2023E2022E2020E 2021E
6,475 6,5506,450 6,475
Note: CapEx numbers are rounded to nearest $25M and numbers may not sum due to rounding
(1) Rate base reflects year-end estimates
Rate Base ($B)(1)
15.3 16.6 17.9 19.1 20.4
10.811.5
11.912.7
13.4
7.88.4
9.210.0
10.96.9
7.78.3
8.9
9.5
2019E 2020E 2021E 2022E 2023E
40.8
44.2
47.3
50.7
54.2+7.3%
PECOBGE ComEdPHI
14 Q4 2019 Earnings Release Slides
Exelon Utilities Project EPS* Growth of 6-8% to 2023
$2.30
$0.00
$1.70
$1.80
$2.60
$2.00
$2.10
$2.20
$2.40
$1.90
$2.50
$2.25
$1.91
$2.05
2019A
$2.50
2020E 2021E 2022E
$2.10
$2.60
2023E
$2.20
$1.80Uti
lity
Ad
juste
d O
pe
rati
ng E
arn
ings*
Rate base growth combined with positive regulatory outcomes drive EPS growth
$2.30
Exelon Utilities Operating Earnings*
$1.95
$1.75
Note: Includes after-tax interest expense held at Corporate for debt associated with utility investment
15 Q4 2019 Earnings Release Slides
Exelon Generation: Gross Margin* Update
• 2020 and 2021 Total Gross Margins* are flat due to declining power prices, offset by our hedges; executed $50M of power
new business in 2020
• Behind ratable hedging position reflects our fundamental view of power prices
― ~6-9% behind ratable in 2020 when considering cross commodity hedges
― ~3-6% behind ratable in 2021 when considering cross commodity hedges
Recent Developments
(1) Gross margin* categories rounded to nearest $50M
(2) Excludes EDF’s equity ownership share of the CENG Joint Venture
(3) Mark-to-Market of Hedges assumes mid-point of hedge percentages
(4) Based on December 31, 2019 market conditions
Gross Margin Category ($M)(1) 2020 2021 2020 2021
Open Gross Margin*(2)
(including South, West, New England, Canada hedged gross margin)$3,600 $3,450 $(400) $(100)
Capacity and ZEC Revenues(2) $1,900 $1,850 - -
Mark-to-Market of Hedges(2,3) $850 $350 $450 $100
Power New Business / To Go $450 $750 $(50) -
Non-Power Margins Executed $250 $150 - -
Non-Power New Business / To Go $250 $350 - -
Total Gross Margin*(4) $7,300 $6,900 - -
December 31, 2019Change from
September 30, 2019
16 Q4 2019 Earnings Release Slides
Adjusted O&M* ($M)
Note: All amounts rounded to the nearest $25M and numbers may not sum due to rounding
(1) Capital spend represents cash CapEx with CENG at 100% and excludes merger commitments
Driving Costs and Capital Out of the Generation Business
850775
825825
125 1,675
2020E
75
2021E
1,800
Capital Expenditures ($M)(1)
Committed Growth Nuclear Fuel Base
4,200 4,150
2021E2020E
Continued focus on all O&M and capital costs at ExGen
17 Q4 2019 Earnings Release Slides
Maintaining Strong Investment Grade Credit Ratings is a Top Financial Priority
Current Ratings(3) ExCorp ExGen ComEd PECO BGE ACE DPL Pepco
Moody’s Baa2 Baa2 A1 Aa3 A3 A2 A2 A2
S&P BBB BBB+ A A A A A A
Fitch BBB+ BBB A A+ A A- A A-
(1) Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment
(2) Exelon Corp downgrade threshold (orange dotted line) is based on the S&P Exelon Corp Summary Report; represents minimum level to maintain current Issuer Credit Rating at Exelon Corp
(3) Current senior unsecured ratings as of December 31, 2019, for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco
(4) Reflects net book debt (YE debt less cash on hand) / adjusted operating EBITDA*
ExGen Debt/EBITDA Ratio*(4)Exelon S&P FFO/Debt %*(1,2)
Credit Ratings by Operating Company
20%
0%
5%
10%
15%
20%
25%19%-21%
2020 Target0.0
1.0
2.0
3.0
4.0
2.4x
2020 Target
1.9x
3.0x
Book
Excluding Non-Recourse
S&P Threshold
18 Q4 2019 Earnings Release Slides
$0.71
$0.52
$0.55
$0.37
$1.31
($0.23)
$0.45 - $0.55
2019 Actuals
$1.20 - $1.30
$0.30 - $0.40
($0.20)
$0.50 - $0.60
$0.65 - $0.75
2020 Guidance
$3.22(1)
$3.00 - $3.30(2)
2020 Adjusted Operating Earnings* Guidance
Key Year-Over-Year Drivers
• ExGen: Lower realized energy prices
and capacity revenues and absence
of R&D tax benefit and NDT realized
gains
• BGE: Higher depreciation, partially
offset by higher distribution and
transmission revenues
• PECO: Higher depreciation and
interest, partially offset by higher
transmission revenues
• PHI: Higher distribution and
transmission revenues, partially
offset by higher depreciation
• ComEd: Increased capital
investments to improve reliability in
distribution and transmission, offset
by impact of treasuries
Expect Q1 2020 Adjusted Operating Earnings* of $0.85 - $0.95 per share
Note: Amounts may not sum due to rounding
(1) 2019 results based on 2019 average outstanding shares of 974M
(2) 2020E earnings guidance based on expected average outstanding shares of 978M
19 Q4 2019 Earnings Release Slides
2020 Business Priorities and Commitments
Effectively deploy ~$6.5B of utility capex
Ensure timely recovery on investments to enable customer benefits
Support Enactment of Clean Energy Policies
Grow dividend at 5% rate
Continued commitment to corporate responsibility
Meet or exceed our financial commitments
Maintain industry leading operational excellence
20 Q4 2019 Earnings Release Slides
The Exelon Value Proposition
▪ Regulated Utility Growth with utility EPS rising 6-8% annually from 2019-2023 and rate base growth of 7.3%, representing an expanding majority of earnings
▪ ExGen’s free cash generation will support utility growth, ExGen debt reduction, and the external dividend
▪ Optimizing ExGen value by:
• Seeking fair compensation for the zero-carbon attributes of our fleet;
• Closing uneconomic plants;
• Monetizing assets; and,
• Maximizing the value of the fleet through our generation to load matching strategy
▪ Strong balance sheet is a priority with all businesses comfortably meeting investment grade credit metrics through the 2023 planning horizon
▪ Capital allocation priorities targeting:
• Organic utility growth;
• Return of capital to shareholders with 5% annual dividend growth through 2020(1); and,
• Debt reduction
(1) Quarterly dividends are subject to declaration by the board of directors
21 Q4 2019 Earnings Release Slides
Additional Disclosures
22 Q4 2019 Earnings Release Slides
Exelon Utilities Project EPS Growth of 6-8% to 2023
Utility growth rate remains 6-8%, driven by rate base growth and positive regulatory outcomes
Q4 2018 Operating Earnings*(1) Q4 2019 Operating Earnings*
$0.00
$1.50
$1.70
$1.90
$2.30
$2.00
$2.10
$2.20
$2.40
$2.50
$1.80
$1.60
$2.60
$2.25
2018A
$2.45
$2.15
2020E2019E 2021E 2022E
$1.80
$2.05
$1.95
$1.85
$1.73
$2.15
$1.75
$2.30
$1.80
$2.60
$2.50
$2.00
$0.00
$1.70
$1.90
$2.10
$2.40
$2.20
2022E2021E
$2.50
$2.10
$1.91
2019A 2020E
$2.05
$2.25
$2.60
2023E
$2.20
$1.80
$2.30
$1.95
$1.50 $1.75
Note: Includes after-tax interest expense held at Corporate for debt associated with utility investment
(1) 2018 Actuals were changed from $1.74 to $1.73 to reflect the correction of an error at PHI
23 Q4 2019 Earnings Release Slides
Utility Capex and Rate Base vs. Previous Disclosure
We plan to invest $25.9B of capital in utilities from 2020-2023, supporting rate base growth
of 7.3% from 2019-2023
3,675 3,850 3,875 4,125
9501,275 1,100
1,075700
800 775 700
5,750
2020E2019E 2021E
5,925
2022E
5,875
5,325
25.2 27.6 29.5 31.4 33.5
8.28.8 9.2 9.6
10.36.3
6.8
2022E2018E 2020E
4.25.5
4.9
2019E 2021E
37.641.2
44.247.3
50.7+7.8%
3,7004,300 4,075 4,450 4,425
1,000
1,325 1,5501,300 1,300775
850 800 800 750
2019A
6,550
5,475
2020E 2021E 2022E 2023E
6,475 6,450 6,475
27.2 29.5 31.4 33.7 35.9
8.79.1 9.5
10.010.85.6
6.37.0
7.4
4.9
2019E 2020E
40.8
2023E2021E 2022E
44.247.3
50.754.2
+7.3%
Q4 2019 Capital Expenditures ($M)
Q4 2019 Rate Base ($B)
Q4 2018 Capital Expenditures ($M)
Q4 2018 Rate Base ($B)
Gas Delivery/Other(1) Electric DistributionElectric Transmission
Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates.
(1) Other includes long-term regulatory assets, which earn a return consistent with rate base, including Energy Efficiency and the Solar Rebate Program
24 Q4 2019 Earnings Release Slides
Mechanisms Cover Bulk of Rate Base Growth
2.1
8.7
1.3
2.1
2.2
2.5 4.6
1.0
1.2
1.0
2020E Total2021E 2022E 2023E
3.4
3.4
3.1
3.5 13.4
Of the ~$13.4B of rate base growth Exelon Utilities forecasts over the next 4
years, ~65% will be recovered through existing formula and tracker mechanisms
Rate Base Growth Breakout 2020–2023 ($B)
Base Rate Case
Tracker/Formula Rate
Note: Numbers may not sum due to rounding
25 Q4 2019 Earnings Release Slides
Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates.
(1) Other includes long-term regulatory assets, which earn a return consistent with rate base, including Energy Efficiency and the Solar Rebate Program
ComEd Capital Expenditure and Rate Base Forecast
1,5751,900 1,825 1,950 1,950
325
475 500 450 5001,900
2022E2020E 2021E2019A 2023E
2,350 2,325 2,400 2,450
Project ~$9.5B of Capital being invested from 2020-2023
11.0 12.0 12.9 13.8 14.7
3.7 3.8 4.0 4.2 4.60.6
2019E
1.0
2020E
0.7
2022E2021E
0.91.1
2023E
15.3 16.6 17.9 19.1 20.4
+7.5%
1,575 1,725 1,875 2,000
300450 325
425
2019E
2,1752,150
2020E 2021E 2022E
1,875
2,425
10.3 11.3 12.1 13.0 14.1
3.5 3.7 3.8 4.0 4.0
2019E
0.80.4 0.6
19.2
2018E 2020E
1.0
2021E
1.1
2022E
14.2 15.6 16.7 18.0
+7.8%
Other(1) Electric DistributionElectric Transmission
Q4 2019 Capital Expenditures ($M)
Q4 2019 Rate Base ($B)
Q4 2018 Capital Expenditures ($M)
Q4 2018 Rate Base ($B)
26 Q4 2019 Earnings Release Slides
Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates.
PECO Capital Expenditure and Rate Base Forecast
Q4 2019 Capital Expenditures ($M)
650 700 700825 875
200250
275300 275 250
2021E
100
1,225
2019A
125
75
2022E2020E
125
2023E
1,0001,125
1,200 1,200
Project ~$4.8B of Capital being invested from 2020-2023
4.9 5.3 5.7 6.3 6.9
1.9 2.12.4
2.62.7
2021E2020E
1.0
2019E
1.0 1.11.2
2022E
1.3
2023E
7.8 8.49.2
10.010.9
+8.5%
Q4 2019 Rate Base ($B)
Q4 2018 Capital Expenditures ($M)
Q4 2018 Rate Base ($B)
600 575 600 650
250 300 300 250
125 50
2019E
125 50
975
2020E 2021E 2022E
975 1,000 975
4.4 5.0 5.3 5.6 6.0
1.71.9 2.1 2.3 2.5
1.1
1.01.1
2018E
1.1
2020E
9.7
1.0
2019E 2021E 2022E
7.17.9 8.4
9.1
+8.2%
Gas Delivery Electric DistributionElectric Transmission
27 Q4 2019 Earnings Release Slides
Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates.
BGE Capital Expenditure and Rate Base Forecast
525 575 500 500 475
200275
300 200 250
450475
400450 425
2022E 2023E2019A 2020E 2021E
1,175
1,3001,200 1,125 1,150
Project ~$4.8B of Capital being invested from 2020-2023
3.7 4.0 4.3 4.5 4.7
1.2 1.4 1.5 1.6 1.82.02.3 2.5 2.8
3.06.9
2019E 2020E 2021E 2022E 2023E
7.78.3
8.99.5
+8.2%
475 525400 400
225275
225 175
400450
425375
1,100
2019E 2020E 2021E 2022E
950
1,250
1,075
3.4 3.7 4.0 4.1 4.3
1.3 1.4 1.5 1.71.7 2.02.3 2.5 2.7
2020E
1.1
2019E2018E 2022E2021E
6.36.9
7.7 8.18.7
+8.3%
Electric DistributionElectric TransmissionGas Delivery
Q4 2019 Capital Expenditures ($M)
Q4 2019 Rate Base ($B)
Q4 2018 Capital Expenditures ($M)
Q4 2018 Rate Base ($B)
28 Q4 2019 Earnings Release Slides
PHI Consolidated Capital Expenditure and Rate Base Forecast
975 1,125 1,050 1,175 1,150
375450 550
550 450
2019A 2021E
1,700
75
75100
2022E2020E
1,675
1,42575
75
2023E
1,8001,675
Project ~$6.9B of Capital being invested from 2020-2023
7.6 8.2 8.5 9.1 9.7
2.8 2.9 2.9 3.0 3.110.8
2022E
0.6
12.7
0.4
13.4
2019E 2021E
0.4
2020E
0.50.6
2023E
11.5 11.9
+5.7%
1,025 1,025 1,000 1,075
300 425 475 425
5050
2022E
75
2019E
1,525
2021E
75
2020E
1,3751,550 1,550
7.1 7.6 8.1 8.7 9.2
2.6 2.8 2.9 3.0 3.40.4
2021E
0.5
2019E
10.8
0.3
2018E 2020E
0.40.5
2022E
10.011.4 12.1
13.1
+7.0%
Electric DistributionGas Delivery Electric Transmission
Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates.
Q4 2019 Capital Expenditures ($M)
Q4 2019 Rate Base ($B)
Q4 2018 Capital Expenditures ($M)
Q4 2018 Rate Base ($B)
29 Q4 2019 Earnings Release Slides
ACE Capital Expenditure and Rate Base Forecast
200 225 225 200 175
175 150 150125
125
375
2019A 2022E2020E 2021E 2023E
350 350
325300
Project ~$1.4B of Capital being invested from 2020-2023
1.6 1.7 1.8 1.8 2.0
0.9 1.0 1.0 1.11.1
2.5
2019E 2022E2020E 2021E 2023E
2.6 2.8 2.83.1
+5.5%
175 200 175 150
150150
150
100
250
350
2019E
325
2020E
300
2022E2021E
1.5 1.6 1.7 1.8 1.9
0.8 0.9 1.01.0 1.12.3
2018E 2019E 2020E 2021E 2022E
2.52.6
2.9 3.0+7.7%
Electric Transmission Electric Distribution
Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates.
Q4 2019 Capital Expenditures ($M)
Q4 2019 Rate Base ($B)
Q4 2018 Capital Expenditures ($M)
Q4 2018 Rate Base ($B)
30 Q4 2019 Earnings Release Slides
Delmarva Capital Expenditure and Rate Base Forecast
175225
175 200 225
100
125
100100
10075
100
7575
75
2019A 2020E 2023E2021E 2022E
450
350 375375
400
Project ~$1.6B of Capital being invested from 2020-2023
1.7 1.8 1.9 1.9 2.0
1.0 1.0 1.0 1.0 1.0
0.5 0.6 0.6
2021E
0.4
2022E2019E 2023E
0.4
2020E
3.1 3.3 3.4 3.5 3.6
+3.9%
200 200 175 200
100 12575
100
5075
7550
2021E
375
2022E2019E 2020E
325350325
1.6 1.7 1.8 1.9 1.9
0.9 1.0 1.0 1.0 1.0
0.4 0.4 0.5 0.5
0.3
2018E 2019E 2020E 2021E 2022E
2.9 3.1 3.2 3.3 3.5
+4.4%
Gas Delivery Electric Transmission Electric Distribution
Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates.
Q4 2019 Capital Expenditures ($M)
Q4 2019 Rate Base ($B)
Q4 2018 Capital Expenditures ($M)
Q4 2018 Rate Base ($B)
31 Q4 2019 Earnings Release Slides
Pepco Capital Expenditure and Rate Base Forecast
600 675 650775 725
175325
325225
2020E 2021E
100
2019A 2023E2022E
875
700
975
1,100
975
Project ~$3.9B of Capital being invested from 2020-2023
4.3 4.7 4.8 5.4 5.7
0.90.9 0.9
0.9 1.0
2022E2020E2019E 2021E
5.2
2023E
5.6 5.76.3
6.7+6.8%
650 625 625750
175 250225
900
2021E2019E
800
75
2022E2020E
725
950
4.0 4.3 4.6 5.0 5.4
0.90.9 0.9 0.9
1.24.9
2022E
6.6
2020E2019E2018E 2021E
5.3 5.6 5.9
+8.1%
Electric Transmission Electric Distribution
Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates.
Q4 2019 Capital Expenditures ($M)
Q4 2019 Rate Base ($B)
Q4 2018 Capital Expenditures ($M)
Q4 2018 Rate Base ($B)
32 Q4 2019 Earnings Release Slides
4,200 4,150
2021E2020E
ExGen O&M and Capex vs. Previous Disclosure
850 775
825 825
1,6751,800
125
2021E2020E
75
Committed Growth BaseNuclear Fuel
875 825 825
900 900 775
200150 1,750
2019E 2020E
150
1,925
2021E
1,900
4,325 4,250 4,200
2019E 2020E 2021E
Adjusted O&M* - Q4 2019 ($M)
CapEx – Q4 2019 ($M)(1)
Adjusted O&M* - Q4 2018 ($M)
CapEx – Q4 2018 ($M)(1)
Note: All amounts rounded to the nearest $25M and numbers may not sum due to rounding
(1) Capital spend represents cash CapEx with CENG at 100% and excludes merger commitments
33 Q4 2019 Earnings Release Slides
Adjusted O&M* Forecast
(1) All amounts rounded to the nearest $25M and may not sum due to rounding
$4,175 $4,200
$1,275 $1,300
$1,000 $1,000
$775 $825
$750 $775
-$100 -$175
2019 Actuals(1)
$7,925
2020 Guidance(1)
7,850
Key Year-over-Year Drivers• BGE: Increase driven by inflation
• PECO: Increase driven by return to
normal storm and inflation
• PHI: Driven by inflation, substation costs
and cyber security costs, offset by cost
management initiatives
• ComEd: Increase driven by inflation
• ExGen: Additional nuclear outages and
lower NEIL distribution, partially offset by
cost management initiative and nuclear
retirement
($ in millions)
ExGenBGE
ComEdPECO
PHI
HoldCo
34 Q4 2019 Earnings Release Slides
2020 Projected Sources and Uses of Cash
Consistent and reliable free cash flows Enable growth & value creationSupported by a strong balance sheet
Strong balance sheet enables flexibility to
raise and deploy capital for growth
✓ $1.7B of long-term debt at the utilities, net
of refinancing, to support continued growth
and $1.5B of ExGen long-term debt
reduction
Operational excellence and financial
discipline drives free cash flow* reliability
✓ Generating $6.1B of free cash flow*,
including $2.1B at ExGen and $4.3B at the
Utilities
Creating value for customers,
communities and shareholders
✓ Investing $6.6B of growth CapEx, with
$6.5B at the Utilities and $0.1B at ExGen
Note: Numbers may not sum due to rounding
(1) All amounts rounded to the nearest
$25M. Figures may not add due to
rounding.
(2) Gross of posted counterparty
collateral
(3) Figures reflect cash CapEx and
CENG fleet at 100%
(4) Anticipated proceeds from
securitization of Constellation
Accounts Receivable Portfolio
(5) Other Financing primarily includes
expected changes in commercial
paper, tax sharing from the parent,
renewable JV distributions, tax
equity cash flows and debt issue
costs
(6) Financing cash flow excludes
intercompany dividends
(7) ExGen Growth CapEx primarily
includes Retail Solar and W.
Medway
(8) Dividends are subject to declaration
by the Board of Directors
(9) Includes cash flow activity from
Holding Company, eliminations and
other corporate entities
($M)(1) BGE ComEd PECO PHI
Total
UtilitiesExGen Corp
(9) ExelonCash
Balance
Beginning Cash Balance*(2) 1,500
Adjusted Cash Flow from Operations(2) 825 1,500 825 1,150 4,275 3,750 (150) 7,900
Base CapEx and Nuclear Fuel(3) - - - - - (1,675) (100) (1,775)
Free Cash Flow* 825 1,500 825 1,150 4,275 2,075 (250) 6,100
Debt Issuances 300 1,000 350 500 2,150 975 900 4,025
Debt Retirements - (500) - - (500) (2,500) (900) (3,900)
Project Financing - - - - - (75) - (75)
Equity Issuance/Share Buyback - - - - - - - -
AR Securitization (4) - - - - - 750 - 750
Contribution from Parent 325 500 225 325 1,350 - (1,350) -
Other Financing(5) 150 300 75 (25) 500 325 (250) 600
Financing*(6) 775 1,300 650 775 3,500 (525) (1,575) 1,400
Total Free Cash Flow and Financing 1,575 2,800 1,475 1,925 7,775 1,550 (1,825) 7,500
Utility Investment (1,300) (2,350) (1,125) (1,675) (6,475) - - (6,475)
ExGen Growth(3,7) - - - - - (125) - (125)
Acquisitions and Divestitures - - - - - - - -
Equity Investments - - - - - (25) - (25)
Dividend(8) - - - - - - - (1,500)
Other CapEx and Dividend (1,300) (2,350) (1,125) (1,675) (6,475) (125) - (8,075)
Total Cash Flow 275 425 350 250 1,325 1,425 (1,825) (575)
Ending Cash Balance*(2) 925
35 Q4 2019 Earnings Release Slides
900
300
1,150
850 833 807 750
360
997
303 258
763
295
833
1,430
675 700900
350
788
1,400
650741 750
1,275
2,150
1,550
2,512
1,189
1,023
500
850
185
175
600
1,225 1,200
500
910
20342020 20432022 20302021 2023 2024 2025 20382026 2027 20362028 204720312029
78
2032 2033 2035 2037 2039 2040 2041 2042 20482044 204920462045
Exelon Debt Maturity Profile(1)
Exelon’s weighted average LTD maturity is approximately 15 years
As of 12/31/19
($M)
EXC RegulatedPHI Holdco ExGen(3) ExCorp
LT Debt Balances (as of 12/31/19)(2)
BGE 3.3B
ComEd 8.7B
PECO 3.6B
PHI 6.6B
ExGen recourse(3)
6.0B
ExGen non-recourse 2.0B
HoldCo 6.3B
Consolidated 36.4B
(1) Maturity profile excludes non-recourse debt, securitized debt, capital leases, fair value adjustments, unamortized debt issuance costs and unamortized discount/premium
(2) Long-term debt balances reflect Q4 2019 10-K GAAP financials, which include items listed in footnote 1
(3) Includes legacy CEG debt of $550M and $258M in 2020 and 2032; and tax-exempt bonds of $412M in 2020
36 Q4 2019 Earnings Release Slides
EPS Sensitivities*
(1) Based on December 31, 2019, market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived from an internal model that is
updated periodically. Power price sensitivities are derived by adjusting the power price assumption while keeping all other price inputs constant. Due to correlation of the various
assumptions, the EPS impact calculated by aggregating individual sensitivities may not be equal to the EPS impact calculated when correlations between the various assumptions are
also considered. ExGen EPS sensitivities assume a marginal tax rate of 25.5%.
2020E 2021E
Henry Hub Natural Gas
+ $1/MMBtu $0.09 $0.31
- $1/MMBtu ($0.08) ($0.29)
NiHub ATC Energy Price
+ $5/MWh $0.01 $0.13
- $5/MWh ($0.01) ($0.13)
PJM-W ATC Energy Price
+ $5/MWh ($0.00) $0.05
- $5/MWh $0.00 ($0.06)
ComEd Distribution ROE $0.03 $0.03
Pension Expense $0.00 $0.02
Cost of Debt ($0.02) ($0.02)
Share count (millions) 978 981
Exelon Consolidated Effective Tax Rate 16% 17%
ExGen Effective Tax Rate 20% 23%
Exelon Consolidated Cash Tax Rate 0% (4%)
ExG
en
EP
S I
mp
ac
t* (1
)In
tere
st
Ra
te
Se
nsit
ivit
y t
o +
50
BP
37 Q4 2019 Earnings Release Slides
Historical Nuclear Capital Investment
650575 575 600 550
700 675600 575 525
100175
250175
175150
2013 2015
92550
25
25
2012
50
2014 2020E
2575
2016
675
850
2550
2017 2018 2019 2021E
975
525600
825
650
775
575
-2.3%
Significant historical investments have mitigated
asset management issues and prepared sites for
license extensions already received, reducing
future capital needs. In addition, internal cost
initiatives have found more cost efficient
solutions to large CapEx spend, such as
leveraging reverse engineering replacements
rather than large system wide modifications,
resulting in baseline CAGR of -2.3%.
(1) Reflects accrual capital expenditures with CENG at 50% ownership. All numbers rounded to $25M.
(2) Baseline includes ownership share of Salem all years. CENG is included at ownership share starting in 2014 (full year)
(3) FitzPatrick included starting in 2017 (9 months only)
(4) Growth represents capital that increases the capacity of the units (e.g., turbine upgrades, power uprates), and capital that extends the license of a site (e.g., License Renewals)
(5) Reflects Exelon ownership share. Includes CENG beginning in April 2014, FitzPatrick beginning in April of 2017, and Oyster Creek and TMI partial year operation in 2018 and 2019,
respectively. Excludes Salem and Fort Calhoun.
(6) Industry average is for major operators excluding Exelon and includes 3 months of Fitzpatrick prior to Exelon acquisition. 2019 industry average (excluding Exelon) was not available at the
time of publication.
Cancelled Growth
Growth(4)
Fukushima
Nuclear Baseline (excluding Fuel) (2,3)
Nuclear Baseline CAGR
92.7%94.1% 94.3% 93.7% 94.6% 94.1% 94.6%
95.7%
84.6%
89.3% 89.2% 90.0% 90.0% 89.2% 89.3%
2012 20162013 20152014 2017 2018 2019
Industry Average Exelon
Nuclear Non-Fuel Capital Expenditures(1) ($M)
Nuclear Capacity Factor(5,6)
38 Q4 2019 Earnings Release Slides
SUSTAINABILITY
Dow Jones Sustainability North America Index
Exelon named to Dow Jones Sustainability North America Index for the
14th consecutive year in recognition of the Corporation’s leading
environmental, social and economic sustainability performance among
North American utility companies.
Energy Star® Partner of the Year: Sustained Excellence
In 2019, Exelon Utilities BGE, ComEd, Delmarva, PECO and Pepco
received the Partner of the Year: Sustained Excellence award from U.S.
EPA in recognition of their continuing leadership efforts in customer
energy efficiency programs
CDP Disclosure
Exelon has been a strong performer in the CDP Climate Change and
Water disclosure surveys for the last ten years.
$51.5 million
Last year, Exelon and its employees committed approximately $51.5
million to non-profit organizations and volunteered a record-setting
250,790 hours.
United Way of Whiteside County “Live United Award”
Exelon received this recognition for its consistent exhibition of
leadership throughout the community, including support for the United
Way in both Whiteside County and around the United States.
United Way of Metropolitan Chicago “Corporate Leadership Award”
Exelon was recognized for its commitment to the community and
partnership with United Way and its partner agencies.
DIVERSITY & INCLUSION
HeForShe
Exelon is a Thematic Champion in the United Nations HeForShe
movement, which focuses on engaging men and boys in the
achievement of global gender equality. Exelon has committed to invest
$3 million to STEM education for young women and to reach retention
parity among men and women by year end 2020.
Billion Dollar Roundtable
For the third consecutive year, Exelon maintained its status as a
member of the Billion Dollar Roundtable, an organization that promotes
supplier diversity for corporations achieving $1 billion or more in annual
direct spending with minority and women-owned businesses.
DiversityInc Top 50 Companies 2019
Exelon ranked No. 24 on DiversityInc's list of Top 50 companies for
diversity, 4th of Top 10 companies for diverse leadership and 10th for
the top 17 companies in hiring for veterans.
Fortune Magazine “World’s Most Admired Companies” 2019
For the twelfth time, Exelon was named to Fortune Magazine’s list for
its high marks among Forbes’ financial soundness, innovation and
quality of management criteria.
Human Rights Campaign “Best Places to Work” 2011-2020
Exelon earned the designation of “Best Place to Work” on HRC’s
Corporate Equality Index for the ninth consecutive year in 2020,
receiving a perfect score of 100.
The Military Times Best for Vets 2013-2019
For the seventh year in a row, Exelon received this recognition for its
commitment to providing opportunities to America's veterans.
Forbes America’s Best Employers For Diversity 2018-2020
For the third consecutive year, Forbes recognized Exelon for its
diversity within executive ranks, diversity as a business imperative and
proactive communication on the issue. Exelon ranked 199th among
the top 500 employers across all industries in the U.S.
Exelon Recognition and PartnershipsSustainability Diversity and Inclusion
Community Engagement
CEO Action for Diversity & Inclusion
Exelon joined the CEO Action for Diversity & Inclusion™ , the largest
CEO-driven business commitment to advance diversity and inclusion
within the work place in order to cultivate a workplace where diverse
perspectives and experiences are welcomed and respected.
Workforce
Wildlife Habitat Council’s Employee Engagement Award
Exelon was recognized for its broad-based engagement with employee
teams around habitat and conservation education activities.
Girl Scouts of Greater Chicago and Northwest Indiana ”Corporate
Appreciation Award”
Exelon has supported this organization for over 25 years, including its
STEM and Robotics programs. This award honors corporations who
have made the world a better place by advancing opportunities for
girls and women.
39 Q4 2019 Earnings Release Slides
Exelon Utilities
40 Q4 2019 Earnings Release Slides
Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug SepRevenue
Requirement
Requested
ROE /
Equity Ratio
Expected
Order
($16.9M)(1,2)
8.91% /
47.97% Dec 4, 2019
$79.0M(1,4)
Elec: 9.70%;
Gas: 9.75% /
N/A(3)
Dec 17, 2019
$160.0M(1,5)
3-Year MYP
10.30% /
50.68% Q4 2020
$18.5M(1)
10.30% /
50.53% Jul 2, 2020
Rate case filed Rebuttal testimony Initial briefs Final commission order
Intervenor direct testimony Evidentiary hearings Reply briefs Settlement agreement
Exelon Utilities’ Distribution Rate Case Updates
Rate Case Schedule and Key Terms
Note: Unless otherwise noted, based on schedules of Illinois Commerce Commission, Maryland Public Service Commission, Pennsylvania Public Utility Commission, Delaware Public Service
Commission, Public Service Commission of the District of Columbia, and New Jersey Board of Public Utilities that are subject to change
(1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings
(2) Revenue requirement in initial filing was a decrease of ($6.4M). Through the discovery period in the current proceeding, ComEd agreed to ~($10.5M) in adjustments to limit issues in the case.
(3) Rate of Return and Return on Equity are used solely for AFUDC, surcharges and regulatory asset carrying charges and sets no precedent
(4) Approved revenue requirement reflects $25.0M increase for electric and $54.0M increase for gas. Increase reflects $7.1M of ERI (electric) and $8.7M of STRIDE (gas) that will be transferred from
the ERI and STRIDE surcharges to base rates.
(5) Reflects 3-year cumulative multi-year plan. Company proposed incremental revenue requirement increases of $84M, $40M and $36M with rates effective November 1, 2020, January 1, 2021
and January 1, 2022, respectively.
CF
IT
RT
EH
IB
RB
FO
SA
ComEd FO
BGE FO
Pepco DC
ElectricRT EH
SA
IT RT
RT
DPL MD
ElectricCF
IB RB
FOEHIT RT IB
41 Q4 2019 Earnings Release Slides
Rate Case Filing Details Notes
Docket No. 19-0387 • April 8, 2019, ComEd filed its annual
distribution formula rate update with the Illinois
Commerce Commission seeking a decrease to
distribution base rates
• October 23, 2019, ComEd received the ALJ
proposed order. No additional adjustments to
the revenue requirement were recommended.
• December 4, 2019, the Commission issued a
Final Order in this case approving the requested
revenue requirement with no disallowances
Test Year January 1, 2018 – December 31, 2018
Test Period 2018 Actual Costs + 2019 Projected Plant
Additions
Common Equity Ratio 47.97%
Rate of Return ROE: 8.91%; ROR: 6.51%
Rate Base (Adjusted) $11,355M
Revenue Requirement Decrease ($16.9M)(1,2)
Residential Total Bill % Decrease (0.7%)
ComEd Distribution Rate Case Filing
Detailed Rate Case Schedule
Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb
Filed rate case
Initial briefs
8/29/2019Evidentiary hearings
9/12/2019
7/17/2019
6/20/2019
Reply briefs
4/8/2019
Commission order 12/4/2019
9/26/2019
Rebuttal testimony
Intervenor testimony
(1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings
(2) Revenue requirement in initial filing was a decrease of ($6.4M). Through the discovery period in the current proceeding, ComEd agreed to ~($10.5M) in adjustments to limit issues in the
case.
42 Q4 2019 Earnings Release Slides
Rate Case Filing Details Notes
Docket No. Case No. 9610 • Case originally filed on May 24, 2019 seeking an
increase in electric and gas distribution revenues
• October 25, 2019, BGE filed a settlement
agreement with the MDPSC. The black box
agreement does not stipulate the ROE, ROR, Capital
structure or Rate Base used to determine the
agreed upon revenue increases.
• December 17, 2019, the Commission issued a Final
Order in this case approving BGE’s proposed
Settlement Agreement
Test Year August 1, 2018 – July 31, 2019
Test Period 8 months actual + 4 months estimated
Common Equity Ratio N/A
Rate of Return(2)
Electric [ROE: 9.70%; ROR: 6.94%]
Gas [ROE: 9.75%; ROR: 6.97%]
Rate Base (Adjusted) N/A
Revenue Requirement Increase $79.0M(1,3)
Residential Total Bill % Increase ~2.9%(4)
BGE Distribution Rate Case Filing
Detailed Rate Case Schedule
May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr
Commission order
10/25/2019
Filed rate case 5/24/2019
10/4/2019
Settlement Agreement
12/17/2019
Rebuttal testimony
9/10/2019Intervenor testimony
(1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings
(2) Rate of Return and Return on Equity are used solely for AFUDC, surcharges and regulatory asset carrying charges and sets no precedent
(3) Approved revenue requirement reflects $25.0M increase for electric and $54.0M increase for gas. Increase reflects $7.1M of ERI (electric) and $8.7M of STRIDE (gas) that will be transferred
from the ERI and STRIDE surcharges to base rates.
(4) Increase expressed as a percentage of a combined electric and gas residential customer total bill
43 Q4 2019 Earnings Release Slides
Multi-Year Plan Case Filing Details Notes
Formal Case No. 1156 • May 30, 2019, Pepco DC filed a three year
multi-year plan (MYP) request with the Public
Service Commission of the District of Columbia
(DCPSC) seeking an increase in electric
distribution base rates
• Size of ask is driven by continued investments
in electric distribution system to maintain and
increase reliability and customer service
• MYP proposes five Performance Incentive
Mechanisms (PIMs) focused on system
reliability, customer service and interconnection
Distributed Energy Resources (DER)
Test Year January 1 – December 31
Test Period 2020, 2021, 2022
Proposed Common Equity Ratio 50.68%
Proposed Rate of Return ROE: 10.30%; ROR: 7.69%
2020-2022 Proposed Rate Base (Adjusted) $2.2B, $2.4B, $2.6B
2020-2022 Requested Revenue Requirement Increase(1,2)
$84M, $40M, $36M
2020-2022 Residential Total Bill % Increase(2)
7.0%, 4.2%, 3.7%
Pepco DC (Electric) Distribution Rate Case Filing
Detailed Rate Case Schedule
May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
3/6/2020
Reply briefs
Filed rate case
Initial briefs
5/30/2019
Commission order expected
Intervenor testimony
Rebuttal testimony 4/8/2020
9/10/2020
6/29/2020 - 7/3/2020Evidentiary hearings
8/26/2020
Q4 2020
(1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings
(2) Company proposed incremental revenue requirement increases with rates effective November 1, 2020, January 1, 2021 and January 1, 2022, respectively
44 Q4 2019 Earnings Release Slides
Rate Case Filing Details Notes
Case No. 9630 • December 5, 2019, Delmarva Power filed an
application with the Maryland Public Service
Commission (MDPSC) seeking an increase in
electric distribution base rates
• Size of ask is driven by continued investments
in electric distribution system to maintain and
increase reliability and customer service
Test Year September 1, 2018 – August 31, 2019
Test Period 12 months actual
Proposed Common Equity Ratio 50.53%
Proposed Rate of Return ROE: 10.30%; ROR: 7.19%
Proposed Rate Base (Adjusted) $858.0M
Requested Revenue Requirement Increase $18.5M(1)
Residential Total Bill % Increase 3.6%
Delmarva MD (Electric) Distribution Rate Case Filing
Detailed Rate Case Schedule
Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov
Initial briefs
Rebuttal testimony
5/8/2020
7/2/2020
4/13/2020 - 4/17/2020
Commission order expected
12/5/2019
Evidentiary hearings
Filed rate case
Intervenor testimony 2/21/2020
3/20/2020
(1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings
45 Q4 2019 Earnings Release Slides
Exelon Generation Disclosures
December 31, 2019
46 Q4 2019 Earnings Release Slides
Portfolio Management Strategy
Protect Balance Sheet Ensure Earnings Stability Create Value
Exercising Market Views
% H
ed
ge
d
Purely ratable
Actual hedge %
Market views on timing, product
allocation and regional spreads
reflected in actual hedge %
High End of Profit
Low End of Profit
% Hedged
Open Generation
with LT ContractsPortfolio Management &
Optimization
Portfolio Management Over TimeAlign Hedging & Financials
Establishing Minimum Hedge Targets
Credit Rating
Capital & Operating
ExpenditureDividend
Capital Structure
47 Q4 2019 Earnings Release Slides
Components of Gross Margin* Categories
Open Gross Margin*
•Generation Gross Margin* at current market prices, including ancillary revenues, nuclear fuel amortization and fuels expense
•Power Purchase Agreement (PPA) Costs and Revenues
•Provided at a consolidated level for all regions (includes hedged gross margin* for South, West, New England and Canada(1))
Capacity and ZEC Revenues
•Expected capacity revenues for generation of electricity
•Expected revenues from Zero Emissions Credits (ZEC)
MtM of
Hedges(2)
•Mark-to-Market (MtM) of power, capacity and ancillary hedges, including cross commodity, retail and wholesale load transactions
•Provided directly at a consolidated level for four major regions. Provided indirectly for each of the four major regions via Effective Realized Energy Price (EREP), reference price, hedge %, expected generation.
“Power” New Business
•Retail, Wholesale planned electric sales
•Portfolio Management new business
•Mid marketing new business
“Non Power” Executed
•Retail, Wholesale executed gas sales
•Energy Efficiency(4)
•BGE Home(4)
•Distributed Solar
“Non Power” New Business
•Retail, Wholesale planned gas sales
•Energy Efficiency(4)
•BGE Home(4)
•Distributed Solar
•Portfolio Management / origination fuels new business
•Proprietary trading(3)
Margins move from new business to
MtM of hedges over the course of the
year as sales are executed(5)
Margins move from “Non power new
business” to “Non power executed” over
the course of the year
Gross margin* linked to power production and salesGross margin* from
other business activities
(1) Hedged gross margins* for South, West, New England & Canada region will be included with Open Gross Margin; no expected generation, hedge %, EREP or reference prices provided for this region
(2) MtM of hedges provided directly for the four larger regions; MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh
(3) Proprietary trading gross margins* will generally remain within “Non Power” New Business category and only move to “Non Power” Executed category upon management discretion
(4) Gross margin* for these businesses are net of direct “cost of sales”
(5) Margins for South, West, New England & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin*
48 Q4 2019 Earnings Release Slides
ExGen Disclosures
(1) Gross margin* categories rounded to nearest $50M
(2) Excludes EDF’s equity ownership share of the CENG Joint Venture
(3) Mark-to-Market of Hedges assumes mid-point of hedge percentages
(4) Based on December 31, 2019 market conditions
Gross Margin Category ($M)(1) 2020 2021
Open Gross Margin (including South, West, New England & Canada hedged GM)
(2)$3,600 $3,450
Capacity and ZEC Revenues(2)
$1,900 $1,850
Mark-to-Market of Hedges(2,3)
$850 $350
Power New Business / To Go $450 $750
Non-Power Margins Executed $250 $150
Non-Power New Business / To Go $250 $350
Total Gross Margin*(4)
$7,300 $6,900
Reference Prices(4) 2020 2021
Henry Hub Natural Gas ($/MMBtu) $2.28 $2.42
Midwest: NiHub ATC prices ($/MWh) $22.45 $22.68
Mid-Atlantic: PJM-W ATC prices ($/MWh) $26.18 $27.45
ERCOT-N ATC Spark Spread ($/MWh)HSC Gas, 7.2HR, $2.50 VOM
$14.07 $9.83
New York: NY Zone A ($/MWh) $24.86 $27.27
December 31, 2019
49 Q4 2019 Earnings Release Slides
ExGen Disclosures
(1) Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes
assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 14 refueling outages in 2020 and
13 in 2021 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 94.0% and 94.2% in 2020 and 2021, respectively at Exelon-operated nuclear plants, at
ownership. These estimates of expected generation in 2020 and 2021 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those
years.
(2) Excludes EDF’s equity ownership share of CENG Joint Venture
(3) Percent of expected generation hedged is the amount of equivalent sales divided by expected generation. Includes all hedging products, such as wholesale and retail sales of power, options and swaps.
(4) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs
associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs, RPM capacity and ZEC revenues, but includes the mark-to-market value of
capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin* in order to determine the
mark-to-market value of Exelon Generation's energy hedges.
(5) Spark spreads shown for ERCOT
Generation and Hedges 2020 2021
Exp. Gen (GWh)(1)
186,100 181,500
Midwest 96,600 95,500
Mid-Atlantic(2) 47,500 48,000
ERCOT 26,300 21,400
New York(2) 15,700 16,600
% of Expected Generation Hedged(3) 91%-94% 61%-64%
Midwest 92%-95% 62%-65%
Mid-Atlantic(2) 99%-102% 67%-70%
ERCOT 81%-84% 52%-55%
New York(2) 78%-81% 50%-53%
Effective Realized Energy Price ($/MWh)(4)
Midwest $27.50 $26.50
Mid-Atlantic(2) $36.50 $31.50
ERCOT(5) $5.00 $7.50
New York(2) $33.00 $27.50
December 31, 2019
50 Q4 2019 Earnings Release Slides
ExGen Hedged Gross Margin* Sensitivities
(1) Based on December 31, 2019 market conditions and hedged position; gas price sensitivities are based on an assumed gas-power relationship derived from an internal model that is
updated periodically; power price sensitivities are derived by adjusting the power price assumption while keeping all other price inputs constant; due to correlation of the various
assumptions, the hedged gross margin* impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin* impact calculated when correlations
between the various assumptions are also considered; sensitivities based on commodity exposure which includes open generation and all committed transactions; excludes EDF’s equity
share of CENG Joint Venture
Gross Margin* Sensitivities (with existing hedges)(1) 2020 2021
Henry Hub Natural Gas ($/MMBtu)
+ $1/MMBtu $115 $405
- $1/MMBtu $(110) $(380)
NiHub ATC Energy Price
+ $5/MWh $15 $165
- $5/MWh $(15) $(165)
PJM-W ATC Energy Price
+ $5/MWh $(5) $60
- $5/MWh $5 $(75)
NYPP Zone A ATC Energy Price
+ $5/MWh $10 $40
- $5/MWh $(20) $(40)
Nuclear Capacity Factor
+/- 1% +/- $25 +/- $30
51 Q4 2019 Earnings Release Slides
4,000
4,500
5,000
5,500
6,000
6,500
7,000
7,500
8,000
8,500
9,000
2020 2021
ExGen Hedged Gross Margin* Upside/Risk A
pp
roxi
ma
te G
ross M
arg
in*
($
millio
n)(1
)
$7,450
$7,100
(1) Represents an approximate range of expected gross margin*, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is sold
into the spot market; approximate gross margin* ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and
potential modeling changes; these ranges of approximate gross margin* in 2020 and 2021 do not represent earnings guidance or a forecast of future results as Exelon has not completed
its planning or optimization processes for those years; the price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as
of December 31, 2019. Gross Margin* Upside/Risk based on commodity exposure which includes open generation and all committed transactions.
$6,550
$7,300
52 Q4 2019 Earnings Release Slides
Row Item Midwest Mid-Atlantic ERCOT New York
South,
West, NE &
Canada
(A) Start with fleet-wide open gross margin
(B) Capacity and ZEC
(C) Expected Generation (TWh) 95.5 48.0 21.4 16.6
(D) Hedge % (assuming mid-point of range) 63.5% 68.5% 53.5% 51.5%
(E=C*D) Hedged Volume (TWh) 60.6 32.9 11.4 8.5
(F) Effective Realized Energy Price ($/MWh) $26.50 $31.50 $7.50 $27.50
(G) Reference Price ($/MWh) $22.68 $27.45 $9.83 $27.27
(H=F-G) Difference ($/MWh) $3.82 $4.05 ($2.33) $0.23
(I=E*H) Mark-to-Market value of hedges ($ million)(1)
$230 $135 ($25) $0
(J=A+B+I) Hedged Gross Margin ($ million)
(K) Power New Business / To Go ($ million)
(L) Non-Power Margins Executed ($ million)
(M) Non-Power New Business / To Go ($ million)
(N=J+K+L+M) Total Gross Margin*
$150
$350
$6,900 million
$3.45 billion
$5,650
$750
$1.85 billion
Illustrative Example of Modeling Exelon Generation2021 Total Gross Margin*
(1) Mark-to-market rounded to the nearest $5M
53 Q4 2019 Earnings Release Slides
Additional ExGen Modeling Data
Total Gross Margin Reconciliation (in $M)(1) 2020 2021
Revenue Net of Purchased Power and Fuel Expense*(2,3) $7,675 $7,325
Other Revenues(4) $(150) $(150)
Direct cost of sales incurred to generate revenues for certain
Constellation and Power businesses$(225) $(275)
Total Gross Margin* (Non-GAAP) $7,300 $6,900
(1) All amounts rounded to the nearest $25M
(2) ExGen does not forecast the GAAP components of RNF separately, as to do so would be unduly burdensome. RNF also includes the RNF of our proportionate ownership share of CENG.
(3) Excludes the Mark-to-Market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices
(4) Other Revenues primarily reflects revenues from variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through regulated rates
and gross receipts tax revenues
(5) ExGen O&M, TOTI and Depreciation & Amortization excludes EDF’s equity ownership share of the CENG Joint Venture
(6) Other reflects Other Revenues excluding gross receipts tax revenues, includes nuclear decommissioning trust fund earnings from unregulated sites, and includes the minority interest in
ExGen Renewables JV
(7) 2020 and 2021 Adjusted O&M* includes $150M of non-cash expense related to the increase in the ARO liability due to the passage of time
(8) 2020 and 2021 TOTI excludes gross receipts tax of $125M
(9) 2021 Depreciation & Amortization is unfavorable to 2020 by ($50M)
Key ExGen Modeling Inputs (in $M)(1,5) 2020
Other(6) $125
Adjusted O&M*(7) $(4,200)
Taxes Other Than Income (TOTI)(8) $(375)
Depreciation & Amortization*(9) $(1,025)
Interest Expense $(325)
Effective Tax Rate 20.0%
54 Q4 2019 Earnings Release Slides
2019A Earnings Waterfalls
55 Q4 2019 Earnings Release Slides
Q4 2019 QTD Adjusted Operating Earnings* Waterfall
$0.58
$0.83
$0.00
2018 ComEd
$0.03($0.01)
BGEPECO
$0.00
PHI
$0.21
CorpExGen 2019
$0.02
$0.10 Market and Portfolio Conditions(1)
$0.09 Lower Operating and Maintenance
Expense (2)
$0.08 R&D Tax Benefit(3)
$0.05 Nuclear Outages(4)
$0.03 Zero Emission Credit Revenue(5)
($0.12) Capacity Pricing
($0.02) Other
$0.01 Distribution Rate
Increase
$0.02 Other
Note: Amounts may not sum due to rounding
(1) Primarily reflects higher realized energy prices
(2) Includes a nuclear insurance credit, the impacts of previous cost management programs and lower pension and OPEB costs
(3) Reflects the benefits related to certain research and development activities that qualify for federal and state tax incentives for the 2010 – 2018 tax years
(4) Reflects the revenue and operating and maintenance expense impacts of lower nuclear outage days in 2019, including Salem
(5) Primarily reflects an increase in New York ZEC prices and the approval of the New Jersey ZEC Program in the second quarter of 2019
$0.03 R&D Tax Benefit(3)
($0.01) Other
$0.02 Distribution Rate Increase
($0.01) Weather & Load
($0.01) Increased Storm Costs
($0.01) Other
$0.01 Distribution and
Transmission Rate Increases
($0.01) Other
56 Q4 2019 Earnings Release Slides
Q4 2019 YTD Adjusted Operating Earnings* Waterfall
$3.12$3.22
BGE2018 ComEd
$0.02 $0.07$0.10
$0.04
PECO PHI
($0.08)
ExGen
($0.05)
Corp 2019
($0.27) Market and Portfolio Conditions(2)
($0.22) Capacity Pricing
$0.20 Lower Operating and Maintenance
Expense(3)
$0.10 Nuclear Outages(4)
$0.08 R&D Tax Benefit(5)
$0.03 Other
($0.03) Income Taxes
($0.01) Interest Expense
$0.03 R&D Tax Benefit(5)
($0.04) Other
Note: Amounts may not sum due to rounding
(1) Primarily reflects the absence of the March 2018 winter storms
(2) Primarily reflects lower realized energy prices
(3) Includes higher nuclear insurance credits, the impacts of previous cost managements programs and lower pension and OPEB costs
(4) Reflects the revenue and operating and maintenance expense impacts of lower nuclear outage days in 2019, excluding Salem, partially offset by the impacts of higher nuclear outage days at
Salem in 2019
(5) Reflects the benefits related to certain research and development activities that qualify for federal and state tax incentives for the 2010 – 2018 tax years
$0.01 Distribution and Energy
Efficiency Investment
$0.01 Transmission Revenues
$0.09 Distribution Rate Increase
($0.01) Transmission Revenues
$0.02 Decreased Storm Costs(1)
($0.03) Unfavorable Weather and Load
$0.05 Distribution Rate Increase
$0.02 Decreased Storm Costs(1)
($0.01) Interest Expense
($0.02) Other
$0.11 Distribution and
Transmission Rate Increases
($0.01) Unfavorable Weather
57 Q4 2019 Earnings Release Slides
2020E Earnings Waterfalls
58 Q4 2019 Earnings Release Slides
ComEd Adjusted Operating EPS* Bridge 2019 to 2020
Note: Drivers add up to mid-point of 2020 adjusted operating EPS* range
(1) Revenue net fuel (RNF)* is defined as operating revenues less purchased power and fuel expense
(2) O&M excludes regulatory items that are P&L neutral
(3) Shares Outstanding (diluted) are 974M in 2019 and 978M in 2020
(4) Guidance assumes an effective tax rate for 2020 of 18.9%
$0.71
$0.12
($0.05)
2019A(3) RNF(1)
($0.06)
($0.02)
O&M(2) D&A Other 2020E(3,4)
$0.65 - $0.75
($0.02) Interest Expense
($0.03) Other
$0.09 Distribution & Transmission
$0.04 Energy Efficiency
($0.03) Treasury Yield Impact
$0.02 Other
($0.03) Energy Efficiency
Amortization
($0.03) D&A
($0.01) Inflation
($0.01) Other
59 Q4 2019 Earnings Release Slides
RNF(1) D&A2019A(3) 2020E(3,4)
($0.03)$0.01
O&M(2)
($0.01)
Other
$0.55
$0.45 - $0.55($0.02)
PECO Adjusted Operating EPS* Bridge 2019 to 2020
Note: Drivers add up to mid-point of 2020 adjusted operating EPS* range
(1) Revenue net fuel (RNF)* is defined as operating revenues less purchased power and fuel expense
(2) O&M excludes regulatory items that are P&L neutral
(3) Shares Outstanding (diluted) are 974M in 2019 and 978M in 2020
(4) Guidance assumes an effective tax rate for 2020 of 10.6%
$0.02 Transmission and
Distribution Revenues/Other
($0.01) Normalized Weather
($0.01) Storms
($0.01) Inflation
($0.01) Other
60 Q4 2019 Earnings Release Slides
$0.37
$0.07
($0.04)
Other2019A(3) RNF(1) 2020E(3,4)
($0.02)
O&M(2)
($0.03)
D&A
$0.30 - $0.40
BGE Adjusted Operating EPS* Bridge 2019 to 2020
Note: Drivers add up to mid-point of 2020 adjusted operating EPS* range
(1) Revenue net fuel (RNF)* is defined as operating revenues less purchased power and fuel expense
(2) O&M excludes regulatory items that are P&L neutral
(3) Shares Outstanding (diluted) are 974M in 2019 and 978M in 2020
(4) Guidance assumes an effective tax rate for 2020 of 19.3%
$0.05 Distribution
$0.02 Transmission($0.02) Taxes
($0.01) Interest Expense
($0.01) Other
($0.01) Inflation
($0.01) Other
61 Q4 2019 Earnings Release Slides
$0.52$0.07
RNF(1)2019A(3)
($0.01)
O&M(2)
($0.04)
D&A
$0.01
Other 2020E(3,4)
$0.50 - $0.60
PHI Adjusted Operating EPS* Bridge 2019 to 2020
Note: Drivers add up to mid-point of 2020 adjusted operating EPS* range
(1) Revenue net fuel (RNF)* is defined as operating revenues less purchased power and fuel expense
(2) O&M excludes regulatory items that are P&L neutral
(3) Shares Outstanding (diluted) are 974M in 2019 and 978M in 2020
(4) Guidance assumes an effective tax rate for 2020 of 10.0%
$0.04 Distribution
$0.03 Transmission
62 Q4 2019 Earnings Release Slides
$1.31
D&A
$0.02
Gross Margin2019A(1)
($0.02)($0.04)
O&M
($0.02)
Other 2020E(1,2)
$1.20 - $1.30
ExGen Adjusted Operating EPS* Bridge 2019 to 2020
($0.14) Capacity Revenues
($0.10) Nuclear Retirements
$0.20 Market Conditions
($0.07) Nuclear Outages
($0.03) NEIL distribution
$0.08 Nuclear Retirements($0.05) NDT Realized Gains
$0.03 Other
Note: Drivers add up to mid-point of 2020 adjusted operating EPS* range
(1) Shares Outstanding (diluted) are 974M in 2019 and 978M in 2020
(2) Guidance assumes a marginal tax rate of 25.5% for 2020
$0.03 Nuclear Retirements
($0.01) Base Capex Depreciation
63 Q4 2019 Earnings Release Slides
Appendix
Reconciliation of Non-GAAP
Measures
64 Q4 2019 Earnings Release Slides
Q4 QTD GAAP EPS Reconciliation
Three Months Ended December 30, 2019 ComEd PECO BGE PHI ExGen Other Exelon
2019 GAAP Earnings (Loss) Per Share $0.15 $0.12 $0.10 $0.07 $0.41 ($0.05) $0.79
Mark-to-market impact of economic hedging activities - - - - 0.10 0.01 0.10
Unrealized gains related to NDT funds - - - - (0.12) - (0.12)
Asset Impairments - - - - - - -
Plant retirements and divestitures - - - - - - -
Cost management program - - - - 0.01 - 0.02
Income Tax-Related Adjustments - - - - - (0.01) (0.01)
Noncontrolling interests - - - - 0.03 - 0.03
2019 Adjusted (non-GAAP) Operating Earnings (Loss) Per
Share$0.15 $0.12 $0.10 $0.07 $0.44 ($0.05) $0.83
Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.
65 Q4 2019 Earnings Release Slides
Q4 QTD GAAP EPS Reconciliation (continued)
Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.
Three Months Ended December 30, 2018 ComEd PECO BGE PHI ExGen Other Exelon
2018 GAAP Earnings (Loss) Per Share $0.15 $0.13 $0.07 $0.06 ($0.18) ($0.07) $0.16
Mark-to-market impact of economic hedging activities - - - - 0.18 - 0.19
Unrealized losses related to NDT funds - - - - 0.25 - 0.25
Plant retirements and divestitures - - - - 0.10 - 0.10
Cost management program - - - - 0.01 - 0.02
Gain on contract settlement - - - - (0.06) - (0.06)
Noncontrolling interests - - - - (0.08) - (0.08)
2018 Adjusted (non-GAAP) Operating Earnings (Loss) Per
Share$0.15 $0.13 $0.07 $0.07 $0.23 ($0.07) $0.58
66 Q4 2019 Earnings Release Slides
Q4 YTD GAAP EPS Reconciliation
Twelve Months Ended December 30, 2019 ComEd PECO BGE PHI ExGen Other Exelon
2019 GAAP Earnings (Loss) Per Share $0.71 $0.54 $0.37 $0.49 $1.16 ($0.25) $3.01
Mark-to-market impact of economic hedging activities - - - - 0.18 0.02 0.20
Unrealized gains related to NDT funds - - - - (0.31) - (0.31)
Asset Impairments - - - - 0.13 - 0.13
Plant retirements and divestitures - - - - 0.12 - 0.12
Cost management program - - - 0.01 0.04 - 0.05
Litigation settlement gain - - - - (0.02) - (0.02)
Asset retirement obligation - - - - (0.09) - (0.09)
Change in environmental liabilities - - - 0.02 - - 0.02
Income Tax-Related Adjustments - - - - 0.01 - 0.01
Noncontrolling interests - - - - 0.09 - 0.09
2019 Adjusted (non-GAAP) Operating Earnings (Loss) Per
Share$0.71 $0.55 $0.37 $0.52 $1.31 ($0.23) $3.22
Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.
67 Q4 2019 Earnings Release Slides
Q4 YTD GAAP EPS Reconciliation (continued)
Twelve Months Ended December 30, 2018 ComEd PECO BGE PHI ExGen Other Exelon
2018 GAAP Earnings (Loss) Per Share $0.69 $0.47 $0.32 $0.41 $0.38 ($0.20) $2.07
Mark-to-market impact of economic hedging activities - - - - 0.25 0.01 0.26
Unrealized losses related to NDT funds - - - - 0.35 - 0.35
Asset Impairments - - - - 0.04 - 0.04
Plant retirements and divestitures - - - - 0.53 - 0.53
Cost management program - - - - 0.04 - 0.05
Asset retirement obligation - - - 0.02 - - 0.02
Gain on contract settlement - - - - (0.06) - (0.06)
Income Tax-Related Adjustments - - - (0.01) (0.03) 0.01 (0.02)
Noncontrolling interests - - - - (0.12) - (0.12)
2018 Adjusted (non-GAAP) Operating Earnings (Loss) Per
Share$0.69 $0.48 $0.33 $0.42(1) $1.39 ($0.18) $3.12
Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.
(1) Amount has been revised to reflect the correction of an error at PHI
68 Q4 2019 Earnings Release Slides
Projected GAAP to Operating Adjustments
• Exelon’s projected 2020 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following:
− Mark-to-market adjustments from economic hedging activities;− Unrealized gains and losses from NDT funds to the extent not offset by contractual accounting as
described in the notes to the consolidated financial statements;− Certain costs related to plant retirements;− Certain costs incurred to achieve cost management program savings;− Other items not directly related to the ongoing operations of the business; and− Generation's noncontrolling interest related to CENG exclusion items.
69 Q4 2019 Earnings Release Slides
GAAP to Non-GAAP Reconciliations(1)
(1) Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP
measure may not be currently available; therefore, management is unable to reconcile these measures
(2) Calculated using S&P Methodology. Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment
Exelon FFO/Debt(2)
= FFO (a)
Adjusted Debt (b)
GAAP Operating Income
+ Depreciation & Amortization
= EBITDA
- Interest Expense
+/- Cash Taxes
+ Nuclear Fuel Amortization
+/- Mark-to-Market Adjustments (Economic Hedges)
+/- Other S&P Adjustments
= FFO (a)
Long-Term Debt (including current maturities)
+ Short-Term Debt
+ Purchase Power Agreement and Operating Lease Imputed Debt
+ Pension/OPEB Imputed Debt (after-tax)
+ AR Securitization Imputed Debt
- Off-Credit Treatment of Non-Recourse Debt
- Cash on Balance Sheet
+/- Other S&P Adjustments
= Adjusted Debt (b)
Exelon FFO Calculation(2)
Exelon Adjusted Debt Calculation(1)
70 Q4 2019 Earnings Release Slides
GAAP to Non-GAAP Reconciliations(1)
ExGen Debt/EBITDA = Net Debt (a)
Operating EBITDA (b)
Long-Term Debt (including current maturities)
+ Short-Term Debt
- Cash on Balance Sheet
= Net Debt (a)
GAAP Operating Income
+ Depreciation & Amortization
= EBITDA
+/- GAAP to Operating Adjustments
= Operating EBITDA (b)
ExGen Debt/EBITDA = Net Debt (c)
Excluding Non-Recourse Operating EBITDA (d)
Long-Term Debt (including current maturities)
+ Short-Term Debt
- Cash on Balance Sheet
- Non-Recourse Debt
= Net Debt Excluding Non-Recourse (c)
GAAP Operating Income
+ Depreciation & Amortization
= EBITDA
+/- GAAP to Operating Adjustments
- EBITDA from Projects Financed by Non-Recourse Debt
= Operating EBITDA Excluding Non-Recourse (d)
ExGen Net Debt Calculation
ExGen Operating EBITDA Calculation
ExGen Net Debt Calculation Excluding Non-Recourse
ExGen Operating EBITDA Calculation Excluding Non-
Recourse
(1) Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly
comparable GAAP measure may not be currently available; therefore, management is unable to reconcile these measures
71 Q4 2019 Earnings Release Slides
GAAP to Non-GAAP Reconciliations
Q4 2019 Operating TTM ROE Reconciliation ($M) PHI UtilitiesLegacy EXC
UtilitiesConsolidated EU
Net Income (GAAP) $488 $1,577 $2,065
Operating Exclusions $24 $6 $30
Adjusted Operating Earnings $512 $1,583 $2,095
Average Equity $5,557 $15,355 $20,913
Operating TTM ROE (Adjusted Operating Earnings/Average Equity) (Non-GAAP) 9.2% 10.3% 10.0%
Q4 2018(1) Operating TTM ROE Reconciliation ($M) PHI UtilitiesLegacy EXC
UtilitiesConsolidated EU
Net Income (GAAP) $400 $1,437 $1,836
Operating Exclusions $25 $7 $32
Adjusted Operating Earnings $425 $1,444 $1,869
Average Equity $5,122 $14,245 $19,367
Operating TTM ROE (Adjusted Operating Earnings/Average Equity) (Non-GAAP) 8.3% 10.1% 9.6%
Note: Represents the twelve-month period ending December 31, 2019 and December 31, 2018. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas
Distribution, and Electric Transmission).
(1) Q4 2018 TTM ROE* for PHI and Consolidated EU was changed from 8.4% and 9.7%, respectively, to 8.3% and 9.6%, respectively, to reflect the correction of an error at PHI
72 Q4 2019 Earnings Release Slides
GAAP to Non-GAAP Reconciliations
2020 Adjusted Cash from Ops Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon
Net cash flows provided by operating activities (GAAP) $825 $1,500 $825 $1,150 $5,225 ($150) $9,375
Other cash from investing activities - - - - ($275) - ($275)
Counterparty collateral activity - - - - ($450) - ($450)
AR Securitization - - - - ($750) - ($750)
Adjusted Cash Flow from Operations (Non-GAAP) $825 $1,500 $825 $1,150 $3,750 ($150) $7,900
2020 Cash From Financing Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon
Net cash flow provided by financing activities (GAAP) $525 $800 $300 $400 ($3,150) $275 ($850)
Dividends paid on common stock $250 $500 $350 $375 $1,875 ($1,850) $1,500
AR Securitization - - - - $750 - $750
Financing Cash Flow (Non-GAAP) $775 $1,300 $650 $775 ($525) ($1,575) $1,400
Exelon Total Cash Flow Reconciliation(1) 2020
GAAP Beginning Cash Balance $2,425
Adjustment for Cash Collateral Posted ($925)
Adjusted Beginning Cash Balance(3) $1,500
Net Change in Cash (GAAP)(2) ($575)
Adjusted Ending Cash Balance(3) $925
Adjustment for Cash Collateral Posted ($450)
GAAP Ending Cash Balance $475
(1) All amounts rounded to the nearest $25M. Items may not sum due to rounding.
(2) Represents the GAAP measure of net change in cash, which is the sum of cash flow from operations, cash from investing activities, and cash from financing activities. Figures reflect cash
capital expenditures and CENG fleet at 100%.
(3) Adjusted Beginning and Ending cash balances reflect GAAP Beginning and End Cash Balances excluding counterparty collateral activity
73 Q4 2019 Earnings Release Slides
GAAP to Non-GAAP Reconciliations
ExGen Adjusted O&M Reconciliation ($M)(1) 2019 2020 2021
GAAP O&M $4,725 $4,800 $4,750
Decommissioning(2) $200 $75 $75
Direct cost of sales incurred to generate revenues for certain Constellation and
Power businesses(3)($275) ($225) ($275)
O&M for managed plants that are partially owned ($400) ($425) ($425)
Other ($75) ($25) -
Adjusted O&M (Non-GAAP) $4,175 $4,200 $4,150
Note: Items may not sum due to rounding
(1) All amounts rounded to the nearest $25M
(2) Reflects asset retirement obligation update for TMI and earnings neutral O&M
(3) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin*